Well production system

ABSTRACT

A system and a method for producing fluids from a subterranean well are provided. More specifically, a pumping system and a method operative to utilize at least two downhole pump assemblies to produce hydrocarbons from at least two locations of a subterranean reservoir is provided, the pump assemblies being controllably adjusted to synergistically provide uniform drawn down from the wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority to U.S. ProvisionalApplication No. 62/196,536, filed Jul. 24, 2015, the entirety of whichis incorporated herein by reference.

FIELD OF THE DISCLOSURE

Embodiments herein relate to a system and a method for producing fluidsfrom a subterranean well. More specifically, a pumping system and amethod are provided for producing fluid from at least two downholelocations along the lateral section of horizontal wells.

BACKGROUND

Various downhole well configurations, including vertical, directional,or horizontal, are used in oil and gas production from subterraneanformations. With reference to FIG. 1 (PRIOR ART), horizontal wells Wtypically comprise a relatively vertical section V (which may bevertical or off-vertical) and a relatively lateral section L (which mayor may not be horizontal) that are connected by a curved ‘build’section, often referred to as the ‘heel’ H. In almost all cases, thelateral section is the productive target of the well and will beconfigured to allow the inflow of fluids (oil/water/gas) from thereservoir into the wellbore. The configuration of horizontal wells oftenresults in a complex interaction or interference between liquids and gaswithin the lateral and heel sections L,H, compounded by the fact thatthe lateral section L will often undulate significantly along itsoverall trajectory.

For example, horizontal wells can have sub-hydrostatic flowing reservoirpressures that require artificial lift systems to produce the well, butconventional lift systems, such as pumps, gas lifts, or plunger liftsare not suited for installation deeper than the H section of the well(i.e. into the L section of the well). Due to the size constraints,artificial lift systems can often only be positioned in the wellborenear or above the heel section H (FIG. 1, PRIOR ART). When artificiallift systems are not positioned within the productive target area, theresulting inflow of fluids becomes inconsistent, with the majority ofthe produced fluids coming from near the heel section H and less comingfrom the target lateral section L.

Problems arise when the positioning of a pump P creates higher inflowdrawdown from the areas of the reservoir closest to the heel H of thewell (e.g. drainage area “A” in FIG. 1) and less inflow drawdown towardsthe toe T of the well. Even where smaller pumps, such as jet pumps, havebeen extended to be near the mid-point of the lateral section L,substantial flow interference arises because as production progressesover time, gas G flowing upwardly towards the vertical V section travelsagainst the liquids O flowing downwardly towards the pump P intake (FIG.2, PRIOR ART). For instance, oil, water, and gas generally flow in thedirection from the toe T section of the well to the pump P′ intakelocation; however, in the portion of the well between the pump Plocation and the heel H section, gas flows in the opposite directionfrom the flow of liquids (i.e. oil and/or water). Flow interferencearises when the gas G flow winds up sweeping a significant volume ofliquid O up into the vertical V section of the well. This refluxingvolume of liquid O and gas G results in an artificially high flowingbottom hole pressure, which limits the ultimate inflow rate of the well.Consequently, flow interference is undesirable because it diminishes theefficiency of the system. Further, problems arise when sand and othersolids drop out of the produced fluid and build up, plugging thewellbore.

Therefore, there is a need for a well production system that overcomesthe above-noted problems.

SUMMARY

According to a broad aspect there is provided a well production systemfor recovering hydrocarbons from a subterranean formation, the systemcomprising at least one first pump assembly, for recovering thehydrocarbons from a first section of a wellbore within the formation,the first pump assembly operative at a first production rate, and atleast one second pump assembly, for recovering hydrocarbons from asecond section of the same wellbore, the second section being downholefrom the first section in the wellbore and the second pump assemblyoperative at a second production rate. Each of the first and second pumpassembly production rates may be adjusted, independently or incombination, to provide a substantially uniform drawdown along thewellbore.

The present well production system may be utilized in a horizontalwellbore, the horizontal well having substantially vertical and lateralsections connected by an angled heel section. In one embodiment, boththe first and second pump assemblies may be positioned downhole from thevertical section. In another embodiment, both the first and second pumpassemblies may be positioned in the lateral section of the wellbore. Inanother embodiment, the second pump assembly may be positioned downholefrom the first pump assembly, or at least farther than a mid-point alongthe lateral section.

Each of pump assemblies of the present well production system may beoperative to produce hydrocarbons from the wellbore. In one embodiment,each of the pump assemblies may comprise at least one pump, such as ajet pump. The production rates of each pump may be controlledindependently, or in combination. The production rates of each pump maybe adjusted to minimize downhole fluid interference.

In some embodiments, each of the present pump assemblies may furthercomprise a data acquisition tool operative to obtain bottom holepressure and temperature from the wellbore at or near the pump assembly.

In some embodiments, it is further contemplated that the present systemand method may be used to clean sand and other solid contaminants(wellbore debris) that can plug up the wellbore during production. Inone embodiment, it is contemplated that at least one pump assembly (i.e.the downhole assembly at or near the toe T) may be removed andsubstituted with a tubing string operative to flush contaminantsplugging the wellbore, sweeping the contaminants towards the remainingat least one pump assembly. For example, the at least one second pumpassembly and its associated inner tubing string can be temporarilyremoved from the well, leaving the outer tubing string in the well. Theremaining outer tubing string serves to pump high fluid rates into thewell and back to the first jet pump positioned uphole. As a result, sandand other contaminants become swept up in the high rate fluid in thelateral section of the well, towards the upper pump assembly.Concurrently, the at least one first pump assembly positioned uphole isoperated at lift rate sufficiently high such that it lifts all of thehigh rate fluid being pumped down the lower tubing string, and the sandin the lateral are pulled into the upper jet pump and are lifted tosurface.

According to a broad aspect there is provided a method of recoveringhydrocarbons from a wellbore within a subterranean formation, the methodcomprising providing at least one first pump assembly in the wellborefor recovering the hydrocarbons from a first section of the wellbore,the first pump assembly operative at a first production rate, providingat least one second pump assembly in the wellbore for recovering thehydrocarbons from a second section of the wellbore, the second sectionbeing downhole from the first section of the wellbore, the second pumpassembly operative at a second production rate, and adjusting one orboth of the first and second production rates to provide a substantiallyuniform drawdown along the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The embodiments of the present disclosure will now be described by wayof an example embodiment with reference to the accompanying simplified,diagrammatic, scale drawings. In the drawings:

FIG. 1 is a schematic drawing of a prior art well production system;

FIG. 2 is a schematic drawing of another prior art well productionsystem;

FIG. 3 is a schematic drawing of the present well production system,according to one embodiment;

FIG. 4A is a schematic of one multi-string tubing system of the presentproduction system having separate tubing for each of the fluid supplyand return lines;

FIG. 4B is a schematic of another multi-string tubing system of thepresent production system having the fluid supply and return linesconcentrically disposed one within the other;

FIG. 5A is a magnified schematic drawing of the jet pump assembly at ornear the heel section of the well in the well production system of FIG.3;

FIG. 5B is a magnified schematic drawing of the jet pump assembly at ornear the toe of the well in the well production system of FIG. 3;

FIG. 6 is a cross-sectional view of a prior art jet pump; and

FIG. 7 is a cross-section view of the present well production systemwherein the system is in cleanout mode.

DETAILED DESCRIPTION OF THE DISCLOSURE

According to embodiments herein, systems and methods for recoveringhydrocarbons from a subterranean formation are provided, the system andmethods using at least two downhole pump assemblies capable ofsynergistically reducing fluid interference and improving liftperformance of the production system. Each pump assembly, alone or incombination, may be used to throttle downhole fluid flow, optimizinguniform draw down along the well and enhancing production. The presentsystems and methods may further be configured to address sand and othersolid contaminant fallout from the produced fluids, thereby minimizingplugging of the wellbore and further optimizing hydrocarbon production.

When describing the present assemblies, all terms not defined hereinhave their common art-recognized meanings. To the extent that thefollowing description describes a specific embodiment or a particularuse, it is intended to be illustrative only. The description is intendedto cover all alternatives, modifications and equivalents. The scope ofthe claims should not be limited by the preferred embodiments set forthin the examples, but should be given the broadest interpretationconsistent with the description as a whole.

Having regard to FIG. 3, a well production system 10 for recoveringhydrocarbons from a subterranean reservoir or formation is provided. Thepresent well production system 10 is described for use in a wellbore Wformed in a hydrocarbon containing subterranean formation, the wellboreW having a relatively horizontal configuration consisting of asubstantially vertical section V and a substantially lateral section L,connected by a ‘curved’ and ‘angled’ heel section H. The wellbore W hasa proximal end at or near the surface, and a toe T at a distal end awayfrom and opposite the proximal end. The wellbore W may have a casing Cwith or without a well liner, or may simply be a drilled borehole (e.g.one or more sections of the wellbore may be left as openhole uncasedwellbore, with no inserted tubular assembly). The diameter of thewellbore may be consistent along its entire length, or may vary (e.g. atthe casing-liner overlap zone). As would be known in the art, thewellbore W may comprise a plurality of perforations or frac ports Fintermittently spaced along the lateral section L to provide fluidcommunication with the reservoir.

According to embodiments herein, the present well production system 10may comprise the use of at least two pump assemblies positioned withinthe wellbore W in communication with a power fluid pumping unit and afluid return system, both positioned at the surface. Each of the atleast two pump assemblies may be positioned within the wellbore W in amanner to produce hydrocarbons from a drainage area at or near the pumpassembly, each drainage area being distinct or in fluid communicationwith one another. Each of the at least two pump assemblies may bepositioned such that fluid production rates of one or both pumpassemblies can be adjusted to increase or decrease fluid drawdown in thedrainage areas, decreasing downhole fluid interference and improvingoverall production. For example, one advantage of the present system isthat the fluid production rates achieved by of each pump assembly may bethe same or different, and may be controlled (e.g. increased ordecreased) to provide a substantially uniform drawdown along thewellbore W. Preferably, at least one pump assembly may serve toefficiently produce fluids from between the heel H and the toe T of thewellbore W, or along the lateral L section of the well W between the atleast two pump assemblies.

In some embodiments, both of the at least two pump assemblies may bepositioned downhole from (distal to) the heel section H, such that bothof the at least two pump assemblies may be positioned within the lateralsection L of the wellbore, each pump assembly being spaced from oneanother longitudinally along the lateral section L. For example, atleast one ‘proximal’ (heel) pump assembly may be positioned in or nearthe heel H of the well W, and at least one ‘distal’ (toe) pump assemblymay be positioned between the mid-point of the lateral section L of thewell W and the toe T. It should be understood that additional pumpassemblies may also be used.

Without limitation, each pump assembly may be positioned in the wellborevia any downhole tubing configured to provide at least one fluid supplyline (e.g. power fluid injection line) and at least one distinct fluidreturn line (e.g. returning produced fluids to the surface). Forexample, in one embodiment, a fluid injection line and a fluid returnline may be run downhole using a single supply tubing stringconcentrically disposed within a single return tubing string, such thateach pump assembly may be spaced along the dual-tubing string runningdownhole. In such a case, it is contemplated that the system wouldcomprise a single injection line and a single return line for the entirewellbore, the tubing strings having the at least two pump assembliesinstalled along the strings such that they land spaced out along thelateral length of the wellbore (FIG. 4B). In another embodiment, thesupply tubing string and return tubing string may be laterally disposedone from the other (FIG. 4A). In yet another embodiment, each at leastone pump assembly may be positioned downhole using individualdual-tubing string, such that each pump assembly comprises a distinctfluid supply line and a fluid injection line in fluid communicationtherewith (FIGS. 5A,5B). No matter the configuration, it is understoodthat fluid production rates from each pump assembly may be measured,recorded, and analyzed independently from one another. As such, it isone advantage of the present system and method that at least one firstpump assembly positioned at a first section of the wellbore may recoverwellbore fluids from a first drainage area at a first fluid productionrate, while a second pump assembly positioned in a second section of thewellbore may recover wellbore fluids from a second drainage area at asecond production rate, each first and second production rates beingmeasured and analyzed independently from one another. It is understoodthat one advantage of the present system and method is that one or bothfirst and second production rates may be controlled (e.g. increased ordecreased) to provide reduce or minimize downhole fluid interference,providing a substantially uniform drawdown along the well W andparticularly along the lateral L or deviated sections of the well W.

Having regard to FIG. 5A, the first pump assembly comprises a first pump12 positioned in, near, or proximal to the heel H of the wellbore W.Without limitation, and by way of illustration, if the lateral section Lcould be approximately divided into two halves, with the mid-way pointbeing considered as about 50% of the length of the lateral section L, itis contemplated that the first pump 12 may be positioned past the curvedportion of the heel H, and as far as 10% of the distance along thelateral L section of the well. In some embodiments, the first pump 12may be positioned at some approximate point between 10-50% of thedistance along the lateral L section (e.g. approximately between the Hand half-way or near the mid-point of the lateral L section). In someembodiments, the first pump 12 may be positioned at some approximatepoint between 40-50% of the distance along the lateral L section. Insome embodiments, and where applicable, the first pump 12 may bepositioned at, or as close as possible to, the casing-well liner overlapzone or changeover.

Having regard to FIG. 5B, the second pump assembly comprises a secondpump 14 positioned at or near the distal end of the lateral section, ornear the toe T. Without limitation, and by way of illustration, if thelateral section L could be approximately divided into two halves, withthe mid-way point considered as about 50% of the length of the lateralsection L, it is contemplated that the second pump 14 may be positionedfarther downhole along the lateral L section than the first pump 12. Insome embodiments, the second pump 14 may be positioned somewhere betweenthe mid-point of the lateral section L and the toe T, or at least morethan 50% of the distance along the lateral L section of the well. Insome embodiments, the second pump 14 may be positioned at someapproximate point between 51%-90% of the distance along the lateral Lsection. In some embodiments, the second pump 14 may be positioned atsome approximate point between 60%-80%, or approximately 75% of thedistance along the lateral L section. It is desirable that the secondpump 14 be distanced from the toe T (i.e. not at 100% of the lateralsection L). In some embodiments, where desired, it is contemplated thatthe second pump 14 may be positioned at some point between 25% and 50%of the distance along the lateral section L, provided that the secondpump 14 remains positioned downhole from the first pump 12. It should beunderstood that positioning of the at least two pump assemblies may besuch that uphole pump assemblies draw fluids between said pump assemblyand other pump assemblies positioned downhole. As such, uphole pumpassemblies serve to minimize downhole fluid interference, or theinterference caused when gas G flowing uphole travels against liquids Obeing drawn to the downhole pump. Instead, just gas G and liquid O willboth be drawn to the uphole pump intake, improving the ultimate inflowrate of the well W.

As would be known, each pump assembly may be operatively connected tothe fluid pumping system at the surface through a fluid supply tubingstring, and to the fluid return system for receiving production fluidsfrom the pump assembly through a return tubing string. For example, inone embodiment, pumps 12,14 may be in communication with the surface(via piping manifold 15) via inner tubing 12 i,14 i and outer tubing 12o, 14 o. As above, according to embodiments herein, inner tubing 12 i,14i, connected to the fluid supply system, may be enclosed in the outertubing 12 o, 14 o, but fluidly sealed therefrom, preventing power fluidflowing to the pump 12,14 from mixing with produced wellbore fluid.Having regard to FIG. 6, pumps 12,14 may be secured to outer tubing 12o, 14 o by a seal assembly 16 (e.g. packoff seal), such that a returnfluid annulus 18 is defined between the outer surface of inner tubing 12i and the inner surface of the outer tubing 12 o.

Generally, pumps 12,14 may comprise any pump operative to producewellbore fluids from the wellbore. According to embodiments herein, thepumps 12,14 may be any pumps having adjustable production rates (e.g.,individual pump rates may be controllably increased or decreased), suchas the jet pump described in Applicant's co-pending publishedUS2013/0084194, the entire disclosure of which is hereby incorporated byreference. By way of example, pump production rates may be adjusted byadjusting power fluid rates, adjusting the pump's internal componentry,or a combination thereof.

Having regard to FIG. 6, pumps 12,14 may comprise a pump body 20 havingan uphole end and a downhole end. The uphole end of the pump body 20 isfluidly connected to the supply tubing string such that power fluid 25(arrow) may flow into the pump body 20 via fluid inlet 21. As would beknown, the rate of power fluid 25 may be adjusted to control the pumpproduction rates. The pump body 20 further comprises a carrier seat 18adjacent the uphole end, in fluid communication with fluid inlet 21,fluidly connecting between the inner tubing string 12 i, the carrierseat 18 and to a throat 22 supported below the seat 18. The throat 22has a narrow inlet 26 and a widened outlet 28, which is fluidlyconnecting between the diffuser 30 and an annulus A formed between theinner and outer tubing 12 i,12 o. A venturi 31 is releasably supportedwithin the carrier seat 18, forming a gap between the carrier seat 18and the throat 22.

A production fluid intake 32, proximate the downhole end, receivesproduction fluid 33 (arrow) entering the wellbore W through perforationstherein and directs the production fluid 33 to an axially extendingproduction conduit 34 within the pump body 20. The production fluidconduit 34 is fluidly connected between the intake 32 and the carrierseat 18 and the throat 22. A one-way valve 36, typically a standingvalve, is positioned in the production conduit 34 adjacent the intake 32for permitting production fluid 33 to enter the production conduit 34and blocking flow therefrom to below the one-way valve 36.

In operation, power fluid 25 flows from the inner tubing string 12 iinto the venturi 31 via the power fluid inlet 21. The power fluid 25flows past the carrier seat 18 (via ports therein) and the gap formedbetween the carrier seat 18 and the throat 22, creating a lower pressurethereat. The lower pressure condition forms a suction at the carrierseat 18 which induces production fluid 33 to flow into the intake 32,through the one-way valve 36, the production conduit 34 and the carrierseat 18 into the throat 22. The production fluid 33 combines with thepower fluid 25 in the throat 22, which acts as a mixing tube to form areturn fluid 37. As the return fluid 37 reaches the wider end of thethroat 22 and the diffuser 30, the increased cross-sectional areatherein, relative to the venturi 31 and the narrow inlet 26 of thethroat 22, acts to increase the pressure, providing impetus for liftingthe return fluid 37 to surface in the annulus A. As one of skill in theart would appreciate having reference to FIG. 6, substituting oraltering the geometry of the venturi 31 and/or the throat 22 (e.g. forlarger or smaller components) would necessarily result in acorresponding increase or decrease the performance parameters of thepump. It is an advantage that said components may further be substitutedor replaced to replace worn out parts, without having to pull the pump12,14 from the wellbore W, as described in US 2013/0084194. As such,adjusting power fluid 25 rates, and/or pump componentry as described,alone or in combination, may serve to independently throttle the atleast two pump assemblies.

Each pump assembly may be further operative to receive and recorddownhole information from the wellbore W, such as described in US2013/0084194, from each pump assembly location. In one embodiment, atleast one pump assembly may comprise a data-acquisition tool ordata-sensing sub, connected via a communications line (not shown) suchas a small tubing string or an electrical conductor having, for example,hydraulic, electric, or fiber optic communication means. Thecommunications line may serve to connect the data-sensing sub to thepump assembly, such that each pump assembly equipped with a data-sensingsub may be capable of retrieving, for example, downhole informationabout produced wellbore fluids, bottom hole pressure, temperature, orboth, etc. It should be understood that that the data tool may obtainthe desired information without being impacted by unwanted interferencefrom conditions outside the data tool (e.g. pressure and temperaturechanges resulting from flow of power fluid in the tubing and through theventuri nozzle) and, as such, the bottom hole information retrieved fromeach pump assembly may be recorded and analysed to understand theoverall efficacy of the present system. The information measured andretrieved from the data tool may be used to more accurately reflectwellbore drawdown conditions, enabling more efficient adjustment of atleast two pumps assembly production rates. It should be understood,however, that although the data tool information is useful, it is notrequired for the present methodologies. By way of example, an operatormay adjust one or both pump assembly production rates, increasing ordecreasing production from one or more drainage areas along thewellbore, to enhance production from each end of the well (e.g.increased production from both the toe T and the heel H) using theproduction rates themselves, or based upon the production rates incombination with information obtained from the data tool. Without beinglimited to theory, the present system and methods may provide mechanismsfor reducing downhole fluid interference created by conventionalartificial lift systems by controlling the fluid production from atleast two pumping assemblies positioned within the wellbore. Preferably,the present system and methods may provide mechanisms for achievinguniform drawdown along the lateral L or deviated sections of ahorizontal wellbore W.

As would be known, the present data tool may include memory for storingdata, a processor for causing the data to be stored on the memory, and apower source for providing power to the processor. The data tool may ormay not be a real-time data sensing tool for providing data to thesurface in real time through the communications line. The data tool mayor may not receive data when the pump 12,14 is not being operated toproduce return fluid 37.

The information may be retrieved from each pump assembly at the surfaceelectronically or through pressure communication for analysis,processing, and storage. Downhole information from at least one pumpassembly may be used to modify or adjust pump rates of one or more pumpassemblies in order to more achieve uniform draw down from the well andto optimize production therefrom.

According to embodiments herein, a method for recovering hydrocarbonsfrom a wellbore, such as a horizontal wellbore, is provided. The presentmethod comprises providing at least one first pump assembly in thewellbore for recovering the hydrocarbons from a first section of thewellbore at a first production rate, and at least one second pumpassembly in the same wellbore for recovering hydrocarbons from a secondsection of the wellbore at a second production rate. The first andsecond production rates may be independently controlled (e.g. throttled)to provide a substantially uniform drawdown along the well.

The present method may comprise adjusting the first and secondproduction rates based upon samples of fluids produced from the eachfirst and second pump assembly. By interpreting the fluid rate and fluidmixture ratios, water content of production efficiencies at each pumpcan be determined (e.g. whether the water content in the returned fluidis higher from one of the pump assemblies), and accounted for byadjusting (prorating) combined pump assembly injection rates andpressures accordingly, minimizing the amount of overall water produced.Pump assembly injection rates and pressures may further be adjusted bysubstituting internal pump components (e.g. venturi, diffuser). Thepresent method may further comprise collecting the downhole information,such as bottom hole pressure and/or temperature data, and furtheradjusting the injection rates and pressures accordingly.

By way of example, it may be determined that it is desired to draw morefluid from one end of the well W. In such a case, the injection rate(s)at one or more of the pump assemblies may be altered. Alternatively orin addition, one or more pump assemblies may be reconfigured by changingout the venturi nozzle and/or throat and diffuser, increasing ordecreasing the size thereof. As such, if the heel H is determined tohave a high water cut, an operator may decide to increase drawdown atthe toe T, which can be achieved by increasing the injection rate of theat least one second pump 14 and/or modify the nozzle and/or throat sizesin one or both of the pumps 12,14.

According to embodiments herein, it is further contemplated that thepresent system and method may be used to clean sand and other solidcontaminants (wellbore debris) that can plug up the wellbore W duringproduction. For example, having regard to FIG. 7, where desired (i.e.where solid buildup occurs and fluid transport velocity isinsufficient), it is contemplated that at least one pump assembly may beadapted to serve as a flushing string. By way of example, in oneembodiment, the downhole pump assembly may be adapted by removing pump14 and associated inner tubing string 12 i, leaving the lower outertubing string 14 o in the well to act as a flushing tubing string 40.Pressurized flushing fluid 41 flowing through the flushing string 40serves to sweep contaminants built up in the wellbore towards upholepump 12. The production rates of pump 12 can be maximized in order toprovide sufficient velocity to lift the contaminants. It would beappreciated that the cleanout method may be performed at or belowreservoir pressures (e.g. balanced or underbalanced), therebymaintaining bottom hole reservoir pressures and benefitting fromexisting reservoir flow to assist in withdrawing the contaminants. It isan advantage of the present apparatus and methodologies that the atleast one second pump assembly is permanently positioned at or near thetoe, yet can readily be configured as either a jet pump or a flushingstring.

In operation, the present apparatus and methodologies comprise the useof at least two pump assemblies positioned downhole in a subterraneanwellbore for producing fluids from that subterranean wellbore. Each pumpassembly may be suspended within the wellbore via a tubular conduit, theconduit operably providing distinct power fluid supply and producedfluid return lines connected to the surface. Each pump assembly may bepositioned in the lateral section L of the wellbore. Preferably, atleast one pump assembly may be positioned in a first section of thewellbore, while at least one other pump assembly may be positioned in asecond section of the wellbore, the second section being downhole fromthe first section. Each pump assembly may comprise a pump operative toproduce fluids from a drainage area surrounding the pump assembly. Eachpump assembly may further comprise a data acquisition tool for obtainingbottom hole information from the drainage area surrounding the pumpassembly. According to embodiments herein, the performance parameters ofeach of the at least two pump assemblies may be controlled, allowing thewell operator to adjust the pump capacities, minimizing downhole fluidinterference and enabling uniform fluid production from both ends of thewell (i.e. consistently along the lateral section L of the wellbore).The capacities of each pump assembly may be controlled with or withoutthe use of data obtained from the data acquisition tool. The capacitiesof each pump assembly may be controlled by increasing or decreasingpower fluid flow rates, and/or by changing out internal pump componentssuch as the venturi nozzle or throat.

The previous description of the disclosed embodiments is provided toenable any person skilled in the art to make or use the presentinvention. Various modifications to those embodiments will be readilyapparent to those skilled in the art, and the generic principles definedherein may be applied to other embodiments without departing from thespirit or scope of the invention. Thus, the present invention is notintended to be limited to the embodiments shown herein, but is to beaccorded the full scope consistent with the claims, wherein reference toan element in the singular, such as by use of the article “a” or “an” isnot intended to mean “one and only one” unless specifically so stated,but rather “one or more”. All structural and functional equivalents tothe elements of the various embodiments described throughout thedisclosure that are known or later come to be known to those of ordinaryskill in the art are intended to be encompassed by the elements of theclaims. Moreover, nothing disclosed herein is intended to be dedicatedto the public regardless of whether such disclosure is explicitlyrecited in the claims.

We claim:
 1. A well production system for recovering hydrocarbons from asubterranean formation, the system comprising: at least one first pumpassembly, for recovering the hydrocarbons from a first section of awellbore, the first pump assembly operative at a first production rate,at least one second pump assembly, for recovering the hydrocarbons froma second section of the wellbore, the second section being downhole fromthe first section in the wellbore and the second pump assembly operativeat a second production rate, wherein the first and second productionrates may be independently adjusted to provide a substantially uniformdrawdown along the wellbore.
 2. The system of claim 1, wherein thesecond pump assembly is positioned downhole from the first pumpassembly.
 3. The system of claim 1, wherein the wellbore is a horizontalwellbore having substantially vertical and lateral sections, connectedby an angled heel section.
 4. The system of claim 3, wherein both thefirst and second pump assemblies are positioned downhole from thevertical section.
 5. The system of claim 3, wherein both the first andsecond pump assemblies are positioned in the lateral section.
 6. Thesystem of claim 3, wherein the second pump assembly is approximatelypositioned at least farther than a mid-point along the lateral section.7. The system of claim 1, wherein each of the first and the second pumpassemblies are in fluid communication with a power fluid supply systemand a wellbore fluid return system.
 8. The system of claim 1, whereineach of the first and second pump assemblies comprise a pump.
 9. Thesystem of claim 8, wherein each of the pumps is a jet pump.
 10. Thesystem of claim 7, wherein the jet pumps comprise a venturi and diffuserfor controlling the pump capacity.
 11. The system of claim 10, whereineach of the venturi and the diffuser may be substituted to controllablyincrease or decrease the pump capacity.
 12. The system of claim 1,wherein at least one of the first and second pump assemblies furthercomprise a data-acquisition tool.
 13. The system of claim 12, whereinthe data-acquisition tool is operative to receive and record bottom holepressure and temperature from the wellbore at or near the pump assembly.14. The system of claim 1, wherein the at least one second pump assemblyis adapted to serve as a flushing tubing string and the first productionrate is maximized to remove contaminants buildup within the wellbore.15. A method of recovering hydrocarbons from a wellbore within asubterranean formation, the method comprising: providing at least onefirst pump assembly in the wellbore for recovering the hydrocarbons froma first section of the wellbore, the first pump assembly recovering thehydrocarbons at a first production rate, providing at least one secondpump assembly in the wellbore for recovering the hydrocarbons from asecond section of the wellbore, the second section being downhole fromthe first section of the wellbore, the second pump assembly recoveringthe hydrocarbons at a second production rate, and adjusting one or bothof the first and second production rates to provide a substantiallyuniform drawdown along the well.
 16. The method of claim 14, wherein theproduction rates are adjusted by increasing or decreasing the rate ofpower fluid driving the pump, by substituting internal pump componentry,or both.
 17. The method of claim 15, wherein the internal pumpcomponentry controls the fluid flow rates through the pump.
 18. Themethod of claim 15, wherein the internal pump componentry comprise aventuri, a diffuser, or both.
 19. The method of claim 15, wherein themethod further comprises configuring one of the at least one first orsecond pump assemblies to flush contaminant buildup in wellbore, andadjusting the production rate of the remaining at least one pumpassembly to withdrawn the contaminants.
 20. The method of claim 19,wherein the production rate of the remaining at least one pump assemblyis maximized.